Ipsa mv relay co-ordiantion shaik adam

RELAY CO-ORDINATION
BY
SHAIK ABDULLAH ADAM
PRINCIPAL ENGINEER – POWERPROJECTSINDIA – CHENNAI
28 August 2020 info@powerprojectsindia.com +91-996-218-8337
1
IPSA
MV – TRANSFORMER /BASICS

AGENDA - 1
 INTRODUCTION MV RELAY CO-ORDINATION.
 NEED FOR PROTECTION COORDINATION.
 PROTECTION SYSTEM DESING.
 SIGNIFICANCE OF RELAY AND RELEASE .
 OVER CURRENT PROTECTION AND ITS CHARACTERISTICS.
2

INTRODUCTION
 BASIC PHILOSOPHY - S S S ( Selectivity - Sensitivity – Speed)
 The selected protection principle affects the operating speed of the protection,
which has a significant impact on the harm caused by short circuits. The faster
the protection operates, the smaller the resulting hazards, damage and the
thermal stress will be.
 Further, the duration of the voltage dip caused by the short circuit fault will be
shorter, the faster the protection operates. Thus, the disadvantage to other parts
of the network due to undervoltage will be reduced to a minimum.
3

INTRODUCTION
 BASIC PHILOSOPHY
 The fast operation of the protection also reduces post-fault load peaks which, in
combination with the voltage dip, increase the risk of the disturbance spreading
into healthy parts of the network.
 In transmission networks, any increase of the operation speed of the protection
will allow the loading of the lines to be increased without increasing the risk of
losing the network stability.4

INTRODUCTION
 Good and reliable selectivity of the protection is essential in order to limit the
supply interruption to the smallest area possible and to give a clear indication of
the faulted part of the network.
 This makes it possible to direct the corrective action to the faulty part of the
network and the supply to be restored as rapidly as possible.
5

INTRODUCTION
AS PER IEEE242.2001
 Quick isolation of the affected portion of the system while maintaining normal
operation elsewhere.
 Reduction of the short-circuit current to minimize damage to the system, its
components, and the utilization equipment it supplies.
 Provision of alternate circuits, automatic throw overs, and automatic reclosing
devices
6

NEED FOR RELAY COORDINATION
 NEEDS OF RC
 Ensure the Equipment and Personnel Safety.
 To make proper discrimination of faulty portions and healthy portions of the
power system network.
 Reduce the outage time that will ensure the economic aspects.
7

PROTECTION SYSTEM DESIGN
 PROTECTION SCHEME:
 Protection schemes can be divided into two major groups:
a) Unit schemes b) Non-unit schemes :
 UNIT PROTECTION:
 Unit type schemes protect a specific area of the system i.e. a transformer,
transmission line, motor, generator or busbar. The unit protection schemes are
based on Kirchhoff’s Current Law – the sum of the currents entering an area
of the system must be zero.
 Any deviation from this must indicate an abnormal current path. In these
schemes, the effects of any disturbance or operating condition outside the
area of interest are totally ignored and the protection must be designed to
be stable above the maximum possible fault current that could flow through
the protected area.
8

 NON-UNIT PROTECTION:
 The non-unit schemes, while also intended to protect specific areas, have no
fixed boundaries. As well as protecting their own designated areas, the
protective zones can overlap into other areas. While this can be very
beneficial for backup purposes, there can be a tendency for too great an
area to be isolated if a fault is detected by different non unit schemes.
 The most simple of these schemes measures current and incorporates an
inverse time characteristic into the protection operation to allow protection
nearer to the fault to operate first.
9

 NON-UNIT PROTECTION:
 The non unit type protection system includes following schemes:
 Time graded over-current protection.
 Current graded over-current protection.
 Distance or Impedance protection.
 Interlocking protection.
 Differential protection.
10

 PROTECTION SYSTEM DESIGN :
 Protection system design is based on the knowledge that the faults or abnormal
operating conditions can lead to:
 overloads;
 phase-to-ground faults;
 phase to phase and three phase faults.
11

 PROTECTION SYSTEM DESIGN :
 The detection of the above conditions is undertaken by the protective relays,
whose tasks are:
 To quickly isolate the faulted part of the electrical distribution system while
maintaining normal service for the rest of the system and minimizing damage
to the affected portion;
 To ensure that only the protective device nearest the faults opens to remove
the short-circuit, while the other upstream protective devices remain closed.
 The settings of the relays shall be selected to allow a reliable operation of
the system, keeping as long and as much as possible the feeders or the
system in service without risk of damage.
12

TYPE OF PROTECTION
 PROTECTION COORDINATION:
 To achieve the above goals the protective devices shall be properly selected,
adjusted and coordinated to ensure a reliable operation of the electrical system,
keeping as long and as much as possible the feeders or the system in service without
risk of damage.
 Two different kinds of protective devices are used to protect the electrical system, as
per the reference protection and metering diagrams:
 Electromagnetic relays, thermal overload relays and electronic/SST built-in
overcurrent and ground fault releases for low voltage distribution;
 Indirect relays fed from CTs and VTs for overcurrent and short-circuit protection,
motor protection and ground fault protection, for low and high voltage distribution.
13

 PROTECTION COORDINATION:
 For the indirect relays, the microprocessor technology has been selected; the
protection functions which have been considered active in the multifunction
relays are indicated in the setting tables and in the one line diagrams.
14
Relay function ANSI code
Impedance (Distance) 21
Synchro check 25
Undervoltage 27
Reverse Power 32
Phase Current Balance 46
Thermal 49
Overvoltage 59
Frequency 81
Differential 87
AC Time and
Instantaneous Phase
Overcurrent
50/51
Breaker Failure 50BF
AC Time and Instantaneous
Ground Overcurrent
50G/51G
Trip Circuit Supervision 74TC
Time delay blocking relay 62
Auxiliary time delay blocking
relay
62A
Time delay blocking relay for
breaker failure scheme
62BE
Directional ground
overcurrent relay
67N
Directional overcurrent relay 67
TYPE OF PROTECTION

 RC TYPES:
15
SIGNIFICANCE OF RELAY AND RELEASE
RELAY CO-ORDINATION
>1kV <1kV
MV LV
RELAY
RELEASE
OVER CURRENT OVER CURRENTEARTH FAULT EARTH FAULT
TIME OVER CURRENT(TOC)
OR IDMT [51]
DEFINITE MINI’M TIME(DMT)
OR DEFINITE TIME( DT) ,[50]
INSTANTANEOUS [50 I]
LONG [51]
SHORT [50 ]
INSTANTANEOUS [50 I]

 OVER CURRENT PROTECTION:
 It finds its application from the fact that in the event of fault the current will increase to a value several
times greater than maximum load current.
 A relay that operates or picks up when its current exceeds a predetermined value (setting value) is
called Over-current Relay.
 Over-current protection protects electrical power systems against excessive currents which are
caused by short circuits, ground faults, etc.
 Over-current relays can be used to protect practically any power system elements, i.e. transmission
lines, transformers, generators, or motors.
 For feeder protection, there would be more than one over-current relay to protect different sections
of the feeder. These over-current relays need to coordinate with each other such that the relay
nearest fault operates first.
16
OVER CURRENT PROTECTION AND ITS CHARACTERISTICS

 DESIGN PHILOSOPHY OF OVER CURRENT PROTECTION:
 Use time, current and a combination of both time and current are three ways
to discriminate adjacent over-current relays.
 Over-current Relay gives protection against:
 Phase faults.
 Earth faults.
 Winding faults.
17
Discrimination:
Current setting
Time setting
Current and time

 Short-circuit currents are generally several times (5 to 20) full load current.
Hence fast fault clearance is always desirable on short circuits.
 Primary requirement of Over-current protection is that the protection
should not operate for starting currents, permissible over-current, and
current surges. To achieve this, the time delay is provided.
18

 As per IEEE242 , there is NO discrimination co-ordination needed for LV
system but overlapping shall be avoided .
 But MV/HV 200ms minimum of time discrimination /grading is required
while do co-ordination.
19

 CHARACTERISTICS :
Depending on the time of operation of relays, they are categorized as follows:
 TOC – TIME OVER CURRENT (OR) INVERSE DEFINITE MINIMUM TIME ( IDMT) [51]
 Standard / Normal / Moderate Inverse [ IEC/IEEE /ANSI ]
 Long Inverse [ IEC/IEEE /ANSI ]
 Very Inverse [ IEC/IEEE /ANSI ]
 Extreme Inverse [ IEC/IEEE /ANSI ]
 DEFINITE MINIMUM TIME OR DEFINITE TIME [50]
 INSTANTANEOUS [50I]
20

 CHARACTERISTICS :
 TOC – TIME OVER CURRENT (OR) INVERSE DEFINITE MINIMUM TIME ( IDMT) [51]
 Inverse definite minimum time (IDMT) over-current Relay is one in which the
operating time is approximately inversely proportional to the fault current near
pick-up value and then becomes constant above the pick-up value of the
relay.
 The relay will go to a definite time after 20 times of pickup current.
21

TOC – TIME OVER CURRENT (OR) INVERSE DEFINITE MINIMUM TIME ( IDMT) [51]
 From the picture, it is clear that there is some definite time after which the Relay
will operate. It is also clear that the time of operation at Pick-up value is nearly
very high and as the fault current increases the time of operation decreases
maintaining some definite time.
22

 CHARECTERISTICS :
 DEFINITE MINIMUM TIME OR DEFINITE TIME [50]
 This relay is created by applying intentional time delay after crossing pick up
the value of the current. A definite minimum time overcurrent relay can be
adjusted to issue a trip output at an exact amount of time after it picks up.
Thus, it has a time setting adjustment and pickup adjustment.
23

 CHARECTERISTICS :
 INSTANTANEOUS [50I]
 This relay is referred as instantaneous over current relay, as ideally, the relay
operates as soon as the current gets higher than pick upsetting current. There
is no intentional time delay applied. But there is always an inherent time delay
which we cannot avoid practically. In practice, the operating time of an
instantaneous relay is of the order of a few milliseconds..
24

 RELAY SUITABILITY:
 As we discussed earlier , to provide desired settings at relays, ensure that the
minimum and maximum current and time settings available at selected relay. It
can ensured from vendor catalogue of that relay and Also have responsibility
to cross verification of ETAP library relay models are well verse modelled as per
the vendor catalogue.
 All relays, including instantaneous ( 50I ) have some minimum delay to operate
such as relay sensing needs 20ms and breaker operating time is 40ms as an
example.25
RELAY SUITABILITY

 RELAY TRIP TIME CALCULATIONS
 STANDARD FOR RELAY CO-ORDINATION
 EQUIPMENT DETAILS
 BASICS OF CURRENT TRANSFORMER AND ITS CONNECTIONS
 CO-ORDINATION TIME INTERVAL (CTI)
 STATIC AND NUMERICAL RELAYS
26
AGENDA - 1

 RELAY TRIP TIME CALCULATIONS - IEC
 The formula for Trip time of a relay is based its standards and relay manufacturer.
WHERE, as per IEC 60255 -151 -2009CURVES
IActual - Fault Current or Fault current (A)
Iset - Setting Current or Relay pickup current (A)
T - TMS
k,  , β or c - Constants – It will be subjected to vary based on the curves.
27
RELAY TRIP TIME CALCULATION
-1
k
I Actual
I Set

T βX +Trip time ( Top) t(G) =

 RELAY TRIP TIME CALCULATIONS - IEC
WHERE, as per IEC 60255 -151 -2009CURVES
- PLUG SETTING MULTIPLIER [ PSM ]28
I Actual
I Set
-1
k
I Actual
I Set


 RELAY TRIP TIME CALCULATIONS - IEEE
as per IEEE C37.112-1996
WHERE,
IActual - Fault Current or Fault current (A)
Iset - Setting Current or Relay pickup current (A)
T - Time Dial
p , B ,A- Constants – It will be subjected to vary based on the curves.
29
-1
A
I Actual
I Set
p
T BX +Trip time ( Top) t(I) =

 RELAY TRIP TIME CALCULATIONS - IEEE
WHERE, as per IEEE C37.112-1996
- PLUG SETTING MULTIPLIER [ PSM ]30
I Actual
I Set
-1
A
I Actual
I Set
p
T BX +Trip time ( Top) t(I) =

 CONSTANTS VALUES AS PER IEC & ANSI/IEEE
31
TOC CURVES - IEC K  β OR c
STANDARD INVERSE 0.14 0.02 0
LONG INVERSE 120 1 0
VERY INVERSE 13.5 1 0
EXTREME INVERSE 80 2 0
TOC CURVES - IEEE K p B
MODERATE INVERSE 0.0515 0.02 0.01140
VERY INVERSE 19.61 2 0.419
EXTREME INVERSE 28.2 2 0.1217

 TMS SHORT NOTES:
 TIME DIAL OR TIME MULTIPLIER SETTINGS will be adjusted at graph based on
the curve positioning on plotted graph.
 The Desired Cases Are Two , 1)GRAPHS SHALL NOT BE OVER LAPPED AND
2) NEED TO MAINTAIN SOME TIME GRADINGS .
 IEC time multiplier setting (TMS).
 IEEE time dial (TD). In some relays and literature, a TDM (Time Dial Multiplier) is
used, instead of a TD (Time Dial).
 TDM =
32
TD
7

 MODEL CALCULATION: IEC
Given Data: I Actual -132 A , I Set -33.7 A , TMS – 0.6 , CURVE: STANDARD INV
Solution:
Formula Used as per IEC:
33
- 1
k
I Actual
I Set


 MODEL CALCULATION:
 Trip time ( Top) = 3.034 Sec
34
- 1
k
I Actual
I Set

- 1
0.14
132
33.7
0.02
0.6 0X +Trip time ( Top) t(G) =

 MODEL CALCULATION:
Trip time ( Top) = 3.034 Sec Ω 3.04 Sec for fault current 132A and Setting current is
33.7 A
35

 TOC CURVES - PRIOIRITY SELECTION: [51] ( TRIPPING TIME MODERATE)
 SOURCE / INCOMER SIDE - STANDARD INVERSE.
 EQUIPMENT LOAD SIDE- LONG INVERSE/ EXTREME INVERSE / VERY INVERSE.
 IOC - PRIOIRITY SELECTION: [50] ( TRIPPING TIME IMMEDIATE)
 SOURCE / INCOMER /EUIPMENT SIDE - DMT - TIME DELAY / TIME GRADE IS
DESIRED.
 LOAD SIDE – NO INTENTIONAL TIME DELAY ( INHERENT TIME DELAY)
36

 TOC CURVES (IDMT) : [51] ( TRIPPING TIME MODERATE) As per ALSTOM P141
 Phase TOC [51]
 Neutral TOC [51N]
 Ground TOC [51G]
 Sensitive Ground TOC [51SEN]
 Negative Sequence TOC [51NS]
37
PROTECTION PHASE NEUTRAL GROUND SEN .GROUND NEG SEQ
TOC (IDMT) 51 51N 51G 51SG 51NS
LOCATION (TOC)
PREFERRED
ALL TRANSFORMER
MOTOR/
NEUTRAL
FEEDER -- --

 IOC (DMT) : [50] ( TRIPPING TIME IMMEDIATE) as per ALSTOM P141
 Phase IOC [50I]
 Neutral IOC [50N]
 Ground IOC [50G]
 Sensitive Ground IOC [50SG]
 Negative Sequence IOC [50NS]
38
PROTECTION PHASE NEUTRAL GROUND SEN .GROUND NEG SEQ
INSTANTANEOUS 50I 50N 50G 50SG 50NS
DEFINITE/SHORT TIME
(DMT)
50D 50D 50D 50D 50D
LOCATION (INSTANT)
PREFERRED
LOAD SIDE/END
EQUIPMENT
TRANFORMER/
INCOMER
FEEDER -- --

 STANDARDS:
 IEEE Std 242-2001, the IEEE Buff Book™ - IEEE Recommended Practice
for Protection and Coordination of Industrial and Commercial
Power Systems.
 IEEE Std 141-1993 , IEEE Recommended Practice for Electric Power
Distribution for Industrial Plants
The IEEE color books are organized into new form, termed as “The IEEE 3000
standard collection”
 IEEE 3004 Standards: Protection & Coordination
39
STANDARDS FOR RELAY CO-ORDINATION

 STANDARDS:
 IEEE 3004 Standards: Protection & Coordination
 3004.1-2013 - IEEE Recommended Practice for the Application of
Instrument Transformers in Industrial and Commercial Power Systems
 3004.11-2019 - IEEE Recommended Practice for Bus and Switchgear
Protection in Industrial and Commercial Power Systems
 3004.5-2014 - IEEE Recommended Practice for the Application of
Low-Voltage Circuit Breakers in Industrial and Commercial Power
Systems
 3004.8-2016 - IEEE Recommended Practice for Motor Protection in
Industrial and Commercial Power Systems
40
STANDARDS FOR RELAY CO-ORDINATION

 PROTECTION CO-ORDINATION : OVERCURRENT [51] AND EARTH FAULT [51G/N]
 EQUIPMENTS TO BE COVERED :
 TRANSFORMER
 MOTOR
41
EQUIPMENTS DETAILS

 INSTRUMENT TRANFORMERS: CURRENT TRANSFORMER
 STANDARDS FOR INSTRUMENT TRANSFORMERS:
 IEC 61869 1-5(CONVENTIONAL) 6-12 ( NON –CONVENTIONAL).
 IS 2705 1-4
 IEEE C57.31
42
BASICS OF CURRENT TRANSFORMER AND ITS CONNECTIONS

 INTRUMENT TRANFORMERS: CURRENT TRANSFORMER
 A current transformer is a device that is used for the transformation of current
from a higher value into a proportionate current to a lower value.
 Current transformers will be used for measuring and protection purposes.
 STANDARD CT RATIOS: 5A / 1A
 For the secondary current, choose 1 A or 5 A depending on the instrument
or relay, and on the distance between the transformer and the instrument
it is feeding:
- 5A secondary is used when instruments or relays are close to the
transformer, i.e less than 10m (30ft).
- 1A secondary is preferably selected when the distance between the
current transformer and the instrument transformer or the relay is above
10m (30ft). Joule losses(I2r) by wire resistance are 25 times higher with 5A
than with 1A. Its widely choose for protection.
43

 INSTRUMENT TRANFORMERS: CURRENT TRANSFORMER
 PHASE CT / GROUND CT ( CBCT – CORE BALANCED CT)
 CBCT – Preferred on Resistance Grounded System , in order to sense the fault
current which is comparatively low value.
 CBCT ratio is widely used as 50:1A which is independent of the continuous
current flowing through the circuit.
 CBCT ratio is 50:1A for 100A resistance earthed system and CBCT value is LOWER
than the limited current value of the earthed system.
44

CONFIGURATION CT FOR GROUND
PHASE CT CBCT
45
• In built function on Relay to
sense the Ground Fault
Current.
• Not – Suitable for
Resistance Grounded
System.
• A dedicated and high sensitive CT
(CBCT) connected with relay for Ground
fault current.
• Resistance Grounded system has limited
ground fault current to certain value
(100A- 800A) where CBCT is employed to
sense the lowest ground fault current.

CONNECTION CONFIGURATION
 TYPE1: NEUTRAL CURRENT MEASURED –WITHOUT CBCT
46
RELAY
R
Y
B
N
V
S1
S2 S1
S2 S1
S2 V

 TYPE1: NEUTRAL CURRENT NOT MEASURED –WITHOUT CBCT
47
RELAY
R
Y
B
S1
S2 S1
S2 S1
S2

 TYPE1: NEUTRAL CURRENT MEASURED –WITH CBCT
48
RELAY
R
Y
B
G
S1
S2 S1
S2 S1
S2

CTI: IEEE242 – 15.5
 When plotting coordination curves, certain time intervals should be maintained
between the curves of various protective devices to ensure correct selective
operation and to reduce nuisance tripping. Without adequate CTIs, these
protective devices could trip incorrectly.
49
CO-ORDINATION TIME INTERVAL [ CTI ]

 CTI:
 When coordinating inverse time overcurrent relays, the time interval
according to ANSI/ IEEE Std-242 is usually 0.3 to 0.4 seconds. This interval is
measured between relays in series at the instantaneous setting of the
load side feeder circuit breaker relay and upcoming incomer relays.
 The recommended time has the following components:
• circuit breaker opening time (5 cycles): 0.10 seconds
• relay overtravel: 0.10 seconds ( Electromechanical relay)
• safety factor for CT saturation, setting errors, etc.: 0.22 seconds.
 NOTE: CYCLE( T) = 1/ f , Where f- supply frequency [50Hz], then 1 cycle
=1/50 , =20ms (0.02 seconds).
50

 CTI:
 The recommended time has the following components:
Traditional Time ( 200ms)
 Relay Sensing time : 20ms
 Breaker opening time : 40ms
 CT saturation, setting error : 20ms
 Safety factor / Margin : 100ms
So total 180ms ≈ 200ms or 250ms is provided between series relay’s time
discrimination.
51

 CTI:
 The CTI time interval is changing with respect to the country where the
project is executed and plant’s complex network.
52

 CTI CALCULATION:
CTI =
WHERE,
tR – Relay Timing Error IN %
tCT – CT Error IN %
tOP – Breaker Operation Time Max.1000ms( Changeable With Country / Client)
When Fault Occurred The Immediate Breaker Operate To Isolate.
tOV – Over Travel Time of Electro-Mechanical Relay ( Not Applicable for
Numerical relay)
53
2tR + tCT
100
X tOP + tOv + tCB + tAT + tS

 CTI CALCULATION:
CTI =
WHERE,
tCB – Breaker Opening Time ( Vendor catalogue) - 40-45ms.
tAT – Additional Time required by the relay.
tS – Safety factor
When the overcurrent relays have independent definite time delay
characteristics, it is not necessary to include the allowance for CT error. Hence:
54
2tR + tCT
100

 CONCLUSION ON CTI :
CTI =
BETWEEN DOWNSTREAM AND UPSTREAM RELAYS CTI
55
2tR + tCT
100
RELAY TYPE CTI ( ms)
STATIC RELAY / SST MAX 350 NO MIN
ELECTRO MECHANICAL RELAY MIN 400
NUMERICAL RELAY 200 TO 300

 EXAMPLE SCENARIOS:
SCENARIO 1: Load To Source All Feeders are
Cables And Source Incomer [CB7]
Is Located At Plant Premises.
CTI : 200ms each stage .
56

Cables And Source Incomer [CB4]
CTI : Even a single cable always maintain
an additional time interval to avoid nuisance
relations with utility.
So CTI is 600ms at Relay-5 [ utility ]when its
Down stream incomer relay Relay-4 has CTI 400ms.
57

Cables and has Transformer [CB5]
CTI : In order to avoid tripping Transformer HV frequently
respect to LV faults 50- 100ms additional CTI is
added at Transformer HV Relay-5. Avoid frequent
In-rush currents on transformer.
So CTI is 500ms at Relay-5 [ Transformer HV ]when its
Down stream Transformer LV Relay-4 has CTI 400ms.
58

59
RELAYS
RELAY
STATIC ( SST) ELECTRO MECHANICAL
ANALOG
( DIODE)
DIGITAL
(THYRISTER)
NUMERICAL
(MICROPROCESSOR)
NOT WIDELY USED

60
STATIC AND NUMERICAL RELAYS
STATIC NUMERICAL
Less Accuracy High Accuracy
Not compatible to IEC61850 Compatible to IEC61850
Functions are controlled by
microcontroller
Convert all signal into digital and
processed by microprocessors
Disturbance Recorder is not
available
Disturbance Recorder’s report
useful for analysis.
Non –Programmable Programmable

Ipsa mv relay co-ordiantion shaik adam

Recommended

Recommended

More Related Content

What's hot

What's hot (20)

Similar to Ipsa mv relay co-ordiantion shaik adam

Similar to Ipsa mv relay co-ordiantion shaik adam (20)

Recently uploaded

Recently uploaded (20)

Ipsa mv relay co-ordiantion shaik adam